Embodiments of the present invention relate to the determination of a discharge coefficient of a managed pressure drilling choke/valve as a function of valve opening position.
In the hydrocarbon industry, boreholes/wellbores are drilled into subterranean hydrocarbon reservoirs so that the hydrocarbons can be recovered. The drilling of a borehole is typically carried out using a steel pipe known as a drillstring with a drill bit on the lowermost end; the drill bit is normally attached to or is a part of a bottomhole assembly attached to the lower end of the drillstring. In a drilling procedure, the entire drillstring may be rotated using an over-ground drilling motor, or the drill bit may be rotated independently of the drillstring using a fluid powered motor or motors mounted in the drillstring just above the drill bit. As drilling progresses, a flow of drilling fluid is used to carry the debris created by the drilling process out of the wellbore. During the drilling procedure, the drilling fluid is pumped through an inlet line down the drillstring, passes through holes in the drill bit, and returns to the surface via an annular space between the outer diameter of the drillstring and the borehole (the annular space is generally referred to as the annulus).
Drilling fluid is a broad drilling term that may cover various different types of drilling fluids. The term “drilling fluid” may be used to describe any fluid or fluid mixture used during drilling and may cover such things as drilling mud, heavily weighted mixtures of oil or water with solid particles, air, nitrogen, misted fluids in air or nitrogen, foamed fluids with air or nitrogen, and aerated or nitrified fluids.
In practice, the flow of drilling fluid through the drillstring may be used to cool the drill bit as well as to remove the cuttings from the bottom of the borehole. In conventional overbalanced drilling, the density of the drilling fluid is selected so that it produces a pressure at the bottom of the borehole (the “bottom hole pressure” or “BHP”), which is high enough to counter-balance the pressure of fluids in the formation (“the formation pore pressure”). By counter-balancing the pore pressure, the BHP acts to prevent the inflow of fluids from the formations surrounding the borehole into the borehole. However, if the BHP falls below the formation pore pressure, formation fluids, such as gas, oil and/or water may enter the borehole and produce what is known in drilling as a kick. By contrast, if the BHP is high, the BHP may be higher than the fracture strength of the formation surrounding the borehole resulting in fracturing of the formation. When the formation is fractured, the drilling fluid may enter the formation and be lost from the drilling process. This loss of drilling fluid from the drilling process may cause a reduction in BHP and as a consequence cause a kick as the BHP falls below the formation pore pressure. Loss of fluid to the formations as a result of fracturing is known as fluid loss or lost circulation and may be expensive, as a result of lost drilling fluid, and increase the time to drill the borehole. Kicks are also dangerous and the liquid and/or gas surge associated with the influx into the borehole requires handling at surface.
In order to overcome the problems of kicks and/or fracturing of the formation during drilling, a process known as managed pressure drilling (“MPD”) has been developed. In managed pressure drilling various techniques are used to control/manage the BHP during the drilling process. In MPD, the flow of drilling fluid into and out of the borehole is controlled. This means that pumps that pump the fluid into the borehole and chokes that control the flow of fluid out of the borehole are controlled to control the BHP. Additionally, gas may be injected into the drilling fluid to reduce the drilling fluid density and thus reduce the BHP produced by the column of the drilling fluid in the drilling annulus. In general, until recently, MPD techniques have been fairly crude, relying on manual control of the pumps and choke.
In MPD, the annulus may be closed using a pressure containment device. This device comprises sealing elements, which engage with the outside surface of the drillstring so that flow of fluid between the sealing elements and the drillstring is substantially prevented. The sealing elements may allow for rotation of the drillstring in the borehole so that the drill bit on the lower end of the drillstring may be rotated. A flow control device may be used to provide a flow path for the escape of drilling fluid from the annulus. After the flow control device, a pressure control manifold with at least one adjustable choke or valve may be used to control the rate of flow of drilling fluid out of the annulus. When partially closed during drilling, the pressure containment device creates a backpressure in the wellbore, and this back pressure can be controlled by using the adjustable choke or valve on the pressure control manifold to control the degree to which flow of drilling fluid out of the annulus/riser annulus is restricted.
During MPD an operator may monitor and compare the flow rate of drilling fluid into the drillstring with the flow rate of drilling fluid out of the annulus to detect if there has been a kick or if drilling fluid is being lost to the formation. A sudden increase in the volume or volume flow rate out of the annulus relative to the volume or volume flow rate into the drillstring may indicate that there has been a kick. By contrast, a sudden drop in the flow rate out of the annulus/relative to the flow rate into the drillstring may indicate that the drilling fluid has penetrated the formation.
In some MPD procedures, gas may be pumped into the annulus between the drillstring and the borehole wall in order to reduce bottomhole-pressure while drilling. Often, the borehole is lined with a pipe referred to as a casing string that may be cemented to the borehole wall to, among other things, stabilize the borehole and allow for flow of drilling fluids, production of hydrocarbons from the borehole and/or the like. In such aspects, a drilling annulus may be formed by the annulus lying between the drillstring and the casing string.
Annular gas injection is an MPD process for reducing the bottomhole-pressure in a well/borehole. In many annular gas injection systems, in addition to casing in the well, the casing being a tubing that lines the borehole and may in some cases be cemented to the wall of the borehole, there is a secondary annulus. This secondary annulus may be connected by one or more orifices at one or more depths to the primary annulus, through which the drilling fluids flow.
FIG. 1 illustrates a managed pressure drilling system. As depicted, a drillstring 1 is suspended in a wellbore 4 (for purposes of this application the terms wellbore, borehole and well may be used interchangeable). In the upper section of the wellbore 4 there is an inner annulus 2 (also referred to as a drilling annulus) and a first casing string 11 that is hydraulically connected/in fluid communication with an outer annulus 9 through one or more orifices 3. The outer annulus 9 may itself be cased/lined by a second casing string 12.
The depicted concentric casing injection system may be used to inject gas into the wellbore 4 that is being drilled through a subterranean formation. The concentric casing injection system comprises the outer annulus 9, which may also be referred to as a gas injection annulus, that surrounds the inner annulus 2, which may also be referred to as a drilling annulus, which drilling annulus is formed between the drillstring 1 disposed in the borehole and the first casing string 11 lining the borehole.
The gas injection annulus comprises an annulus between the first casing string 11 the second casing string 12, which may be disposed concentrically around or in a different configuration with respect to the first casing string 11. In one embodiment, gas is pumped into outer annulus 9 and through one or more gas injection ports 3 into the inner annulus 2. During, gas injection procedures, the concentric casing injection system may become/be unstable because of among other things the combination of the large volume and compliance of the gas in the outer annulus 9 along with the history dependent hydrostatic head of the inner annulus 2.
During a MPD procedure, drilling fluid (also referred to herein as drilling mud or mud) may be pumped from a pump(s) (not shown) through pipework 8 into the drillstring 1, down which it passes until it exits at a distal end 5, through a drill bit (not shown) or the like, before returning via the inner annulus 2 and return pipework 7 to fluid tanks for handling/preparing the drilling fluid. Between the pipework 7 and the fluid tanks (not shown) there may be chokes 13 and separators (not shown).
The outer annulus 9 and the pipes feeding the top of the drillstring are connected to gas pumps 15, via a valve manifold 10, which may direct gas either to the drillstring feed, to the outer annulus 9 or optionally to both at once. In the MPD procedure, pressure measurements may be made in the outer annulus 9, the inner annulus 2, the drillstring 1, and/or the like (e.g., at pressure transducer 6). In addition to the described equipment, there may be many other pieces of equipment at the surface, such as blow-out-preventers, a rotating-control-head, etc., which are normal with managed-pressure drilling.
In a gas injection MPD system, the one or more flow ports 3 between the outer annulus 9 and the inner annulus 2 may allow drilling mud to flow between the inner annulus 2 and the outer annulus 9. For example, during the drilling process mud may be flowing in the inner annulus 2 and may flow through the one or more flow ports 3 into the outer annulus 9.
Previously, in a MPD procedure, pumps and an outflow valve/choke have been controlled to manage the BHP. Generally, the amount of fluid being pumped into the wellbore has been measured/estimated and the amount of fluid flowing out of the borehole, has been measured/estimated and the pumps/valves/chokes have been adjusted to change the inflow and outflow to maintain the BHP within prescribed limits, or to react to unexpected phenomena in the pressure and/or flowrate.
To better control the outflow and/or to automate the MPD operation, characterization of the choke is necessary so that a choke position can be selected to produce the desired outflow from the borehole. However, characterizing the operation of a MPD drilling choke has previously required flowing the liquid to be used in the MPD operation, a drilling fluid, through the choke, which may be either costly or impracticable with respect to chokes that are deployed in the field. For example, at the time of manufacture the choke may be characterized by flowing drilling fluids through the choke to characterize its operation. In the field, the choke may be taken offline and characterized by flowing drilling fluids through the choke to determine how it operates. Both of these processes are expensive and the in-field characterization may not be practicable.